Exploring, drilling, completing, and operating hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of these expenses, added emphasis has been placed on well access, monitoring and management throughout the productive life of the well. That is to say, from a cost standpoint, an increased focus on ready access to well information and/or more efficient interventions have played roles in maximizing overall returns from the completed well.
By the same token, added emphasis on operator safety may also play a role in maximizing returns. For example, ensuring safety over the course of various offshore operations may also ultimately improve returns. As such, a blowout preventor (BOP), subsurface safety valve and other safety features are generally incorporated into hardware of the well head at the seabed. Thus, production and pressure related hazards may be dealt with at a safe location several hundred feet away from the offshore platform.
In most offshore circumstances, the noted hardware of the well head and other equipment is disposed within a tubular riser which provides cased access up to the offshore platform. Indeed, other lines and tubulars may run within the riser between the noted seabed equipment and the platform. For example, a landing string which provides well access to the newly drilled well below the well head will run within the riser along with a variety of hydraulic and other umbilicals.
One safety measure that may be incorporated into the landing string is a particularly tailored and located weakpoint. The weakpoint may be located in the vicinity of the BOP, uphole of the noted safety valve. Therefore, where excessive heave or movement of the offshore platform translates to excessive stress on the string, the string may be allowed to shear or break at the weakpoint. Thus, an uncontrolled breaking or cracking at an unknown location of the string may be avoided. Instead, a break at a known location may take place followed by directed closing of the safety valve therebelow. As a result, an unmitigated hazardous flow of hydrocarbon through the riser and to the platform floor may be avoided.
Unfortunately, the closing of the safety valve in conjunction with the separation of the tubular thereabove is not always readily attainable. For example, in certain situations, coiled tubing, wireline or other interventional access line may be disposed through the valve at the time the above tubular separation occurs. When this is the case, the valve may be obstructed and unable to close. Thus, hydrocarbons may continue to leak past the valve and travel up the annulus of the riser to the platform with potentially catastrophic consequences.
In order to prevent such hazardous obstructions, the valve may be configured to achieve a cut-through of any interventional access line in combination with closure. So, for example, an internal spring or other valve closure mechanism may be utilized which employs enough force to ensure a cut-through of any obstruction each time that the valve closes.
Unfortunately, utilizing enough force to both close the safety valve and provide any necessary cutting, upon each valve closure may impair routine operation of the valve. That is to say, opening, closing and re-opening of the valve may be routinely desirable throughout the life of the well. For example, this may include opening the valve for production, closing the valve to halt production, and re-opening the valve for the sake of well killing. Whatever the case, if the valve has been closed with force sufficient to achieve cutting, subsequent re-opening of the valve may be a challenge. In the noted well killing example, the introduction of kill fluid at 1,000-1,500 PSI may no longer, be sufficient to attain valve re-opening. Rather, several thousand PSI may be required. This is particularly inefficient given the remote likelihood of any need for actual cutting during valve closure.
Given the inefficiencies of closing the safety valve with sufficient cutting force upon each and every valve closure, alternative safety measures are generally employed where offshore intervention is sought. For example, an operator will generally ensure that offshore interventions are undertaken for shorter durations and in calmer weather conditions. Thus, the chance of a tubular separation is reduced, particularly with an obstructing access line at the safety valve. Of course, weather based operations may result in downtime and/or delays. By the same token, shorter intervention trips in the well may lead to a greater number of trips. Nevertheless, as a practical matter, such precautionary measures are generally utilized, particularly in shallower offshore environments where tubular separations may be more likely. As a result, offshore interventional costs may become quite excessive.